Total distributable cash flow of $39.5 million, a 5% increase from second quarter 2011

Total segment gross margin of $72.9 million, a 12% increase from the prior year period

Adjusted EBITDA of $58.3 million, a 7% increase from the prior year period

Volumes gathered from the Eagle Ford Shale play averaged 490,000 MMBtu/d, a 277% increase from the prior year period

Texas segment NGL production of over 50,000 Bbls/d, an 86% increase from second quarter 2011

2013 Guidance:

Adjusted EBITDA forecasted to range from $300 million to $330 million

Total Distributable Cash Flow forecasted to range from $220 million to $240 million

Common unit distribution growth rate target of 7% to 9%

"Continued strong volume growth from the Eagle Ford Shale and increased volumes at our Saint Jo plant, combined with improving asset performance, led to increased financial results during the second quarter," said R. Bruce Northcutt, Copano's President and Chief Executive Officer. "Our results also benefited from our strategy of transitioning to a more fee-based business, which has reduced the impact of the lower commodity price environment."

"We are pleased with our progress on capital projects and look forward to achieving the full benefits of our Eagle Ford strategy, which will drive cash flow and distribution growth in 2013. At the same time, we have begun to focus on new long-term growth opportunities to create additional value for Copano unitholders," Northcutt added.

Second Quarter Financial Results

Total distributable cash flow increased 5% from a year ago, to $39.5 million for the second quarter of 2012, and 19% from the first quarter of 2012. The increase from the prior-year period was primarily due to:

Second-quarter 2012 total distributable cash flow represents 93% coverage of the second-quarter distribution of $0.575 per unit, based on common units outstanding on the distribution record date.

Revenue for the second quarter of 2012 decreased 8% from the second quarter of 2011 to $317.3 million, and 6% from the first quarter of 2012. Total segment gross margin increased 12% from both the second quarter of 2011 and first quarter of 2012 to $72.9 million. Adjusted EBITDA increased 7% from the second quarter of 2011, to $58.3 million and 16% from first quarter of 2012. Net income to common was $12.2 million for the second quarter of 2012, compared to net loss of $17.4 million for the second quarter of 2011.

Corporate and other activities, which include Copano's commodity risk management efforts, contributed a gain of $3.4 million for the second quarter of 2012 compared to a loss of $10.3 million for the second quarter of 2011 and a loss of $5.1 million for the first quarter of 2012.

Total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures at the end of this news release. Please read "Use of Non-GAAP Financial Measures" beginning on page 6 of this news release.

Second Quarter Operating Results by Segment

Texas

Segment gross margin for Texas increased 6% from the second quarter of 2011 to $49.1 million, and increased 8% from the first quarter of 2012. The increase from the prior year was primarily a result of volume growth from the Eagle Ford Shale and north Barnett Shale Combo plays, partially offset by lower NGL prices and a decline in lean gas volumes, which were displaced by rich gas volumes at the Houston Central complex. Also, the Lake Charles plant, which contributed $2.5 million to Texas gross margin for the second quarter of 2012, did not operate during the prior-year period.

During the second quarter of 2012, the Texas segment provided gathering and processing services for an average of 924,465 MMBtu/d of natural gas, an increase of 39% from the second quarter of 2011. The Texas segment gathered an average of 566,388 MMBtu/d of natural gas, an increase of 28% over the second quarter of 2011, primarily due to increased volumes from the Eagle Ford Shale and north Barnett Shale Combo plays. Volumes processed at Copano's plants and third-party plants in Texas averaged 834,846 MMBtu/d during the second quarter of 2012, an increase of 42% over the second quarter of 2011 primarily due to increased volumes from the north Barnett Shale Combo play and at the Lake Charles plant. Second-quarter NGL production averaged 50,146 Bbls/d at Copano-owned plants and third-party plants, an increase of 86% from the second quarter of 2011 and 42% from the first quarter of 2012, reflecting a substantial increase in the NGL content of volumes at the Houston Central complex, and increased volumes at the Saint Jo plant in the north Barnett Shale Combo play and the Lake Charles plant in Louisiana.

Eagle Ford Gathering, Copano's unconsolidated joint venture with Kinder Morgan, has been in full service since December 2011 and provided gathering services for an average of 252,912 MMBtu/d during the second quarter of 2012. Texas segment gross margin results do not include the financial results and volumes associated with Copano's interest in Eagle Ford Gathering, which is accounted for under the equity method of accounting and shown in Copano's financial statements under "Equity in (earnings) loss from unconsolidated affiliates." For the second quarter of 2012, equity earnings and distributions from Eagle Ford Gathering totaled $9.8 million and $4.8 million, respectively.

Oklahoma

Segment gross margin for Oklahoma was $20.2 million for the second quarter of 2012, a decrease of 30% compared to the second quarter of last year and 17% from the first quarter of 2012. The year-over-year decrease resulted primarily from a decrease of 39% in realized margins on service throughput compared to the second quarter of 2011 ($0.68 per MMBtu in 2012 compared to $1.11 per MMBtu in 2011) due to lower NGL and natural gas prices. This decrease was partially offset by an increase in service throughput attributable to lean gas volume growth from the Woodford Shale play.

The Oklahoma segment gathered an average of 324,915 MMBtu/d of natural gas, an increase of 14% compared to the second quarter of 2011, due primarily to lean gas from the Woodford Shale area, which increased 46% compared to the second quarter of 2011. Volumes processed at wholly-owned and third-party plants in Oklahoma were flat compared to the second quarter of 2011, averaging 158,016 MMBtu/d. Second quarter NGL production at Copano-owned plants and third-party plants averaged 17,028 Bbls/d, a decrease of 2% from the second quarter of 2011.

Rocky Mountains

Segment gross margin for the Rocky Mountains segment totaled $0.2 million in the second quarter of 2012 compared to $0.8 million for the second quarter of 2011 and $0.4 million for the first quarter of 2012. Rocky Mountains segment gross margin results do not include the financial results and volumes associated with Copano's interest in Bighorn Gas Gathering and Fort Union Gas Gathering, which are accounted for under the equity method of accounting and shown in Copano's financial statements under "Equity in (earnings) loss from unconsolidated affiliates."

Average pipeline throughput for Bighorn and Fort Union on a combined basis increased 40% to 747,009 MMBtu/d in the second quarter of 2012 as compared to 533,329 MMBtu/d in the second quarter of 2011. The volume increase is due primarily to producers increasing volumes on Fort Union to access downstream markets; however, because Fort Union has firm volume commitments, the increase did not have a material impact on Copano's equity earnings or distributions. For the second quarter of 2012, combined equity earnings for Bighorn and Fort Union totaled $2.6 million, compared to $0.6 million for the same period in 2011. Combined distributions from Bighorn and Fort Union totaled $7.3 million in the second quarter of 2012, compared to $6.3 million in the second quarter of last year.

Cash Distributions

On July 11, 2012, Copano announced its second quarter 2012 cash distribution of $0.575 per unit, or $2.30 per unit on an annualized basis, for all of its outstanding common units. This distribution is unchanged from the first quarter of 2012 and will be paid on August 9, 2012 to common unitholders of record at the close of business on July 31, 2012.

2013 Guidance

Copano announced today its forecast for certain financial items for 2013, as outlined in the table below:

The above forecasted amounts are based on various assumptions, which include an average natural gas price of $3.80 per MMBtu, weighted-average Mont Belvieu and Conway NGL prices of $33.16 per barrel and $29.34 per barrel, respectively, and an average NYMEX crude price of $90.34 per barrel. Additionally, for the third and fourth quarters of 2013, Copano assumes no conversion of its preferred units then outstanding and payment of cash rather than in-kind preferred unit distributions.

Management does not develop detailed forecasts for certain items, including GAAP revenues, depreciation, amortization and non-cash changes in derivatives, and therefore is unable to provide forecasted net income, a comparable GAAP measure, for the period presented.

With respect to the third and fourth quarters of 2012, management expects to continue to provide quarterly gross margin trends and any material updates to full-year 2012 capital expenditures and expense guidance.

Conference Call Information

Copano will hold a conference call on August 9, 2012 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) to discuss its second quarter 2012 financial results. To participate in the call, dial (480) 629-9645 and ask for the Copano call at least 10 minutes prior to the start time, or access it live over the internet at www.copano.com on the "Investor Overview" page of the "Investor Relations" section of Copano's website.

A replay of the audio webcast will be available shortly after the call on Copano's website. A telephonic replay will be available through August 16, 2012 by calling (303) 590-3030 and using the pass code 4551423#.

Use of Non-GAAP Financial Measures

This news release and the accompanying schedules include non-generally accepted accounting principles, or non-GAAP, financial measures of total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Copano's non-GAAP financial measures may not be comparable to similarly titled measures of other companies, who may not calculate their measures in the same manner.

Copano's management team uses non-GAAP financial measures to evaluate its core profitability and to assess the financial performance of its assets. Subject to the limitations expressed above, Copano believes that investors and other market participants benefit from access to the various financial measures that its management uses in evaluating its performance because it allows them to independently evaluate Copano's performance with the same information used by management.

Copano Energy, L.L.C. is a midstream natural gas company with operations in Texas, Oklahoma, Wyoming and Louisiana. More information is available at http://www.copano.com.

This press release includes "forward-looking statements," as defined by the Securities and Exchange Commission. Statements that address activities or events that Copano believes will or may occur in the future are forward-looking statements. These statements include, but are not limited to, statements about future producer activity and Copano's total distributable cash flow and distribution coverage. These statements are based on management's experience and perception of historical trends, current conditions, expected future developments and other factors management believes are reasonable. Important factors that could cause actual results to differ materially from those in forward-looking statements include the following risks and uncertainties, many of which are beyond Copano's control: the volatility of prices and market demand for natural gas and natural gas liquids; Copano's ability to continue to obtain new sources of natural gas supply and retain its key customers; the impact on volumes and resulting cash flow of technological, economic and other uncertainties inherent in estimating future production; producers' ability to drill and successfully complete and attach new natural gas supplies; the NGL content of new gas supplies; Copano's ability to access or construct new processing, fractionation and transportation capacity; the availability of downstream transportation and other facilities for natural gas and NGLs; mechanical failures and other operational risks affecting the performance of Copano's processing plants and other facilities, higher construction costs or project delays due to inflation, limited availability of required resources, or the effects of environmental, legal or other uncertainties; general economic conditions; the effects of government regulations and policies; and other financial, operational and legal risks and uncertainties detailed from time to time in Copano's quarterly and annual reports filed with the Securities and Exchange Commission.

Proceeds from public offering of common units, net of underwriting discounts

and commissions of $7,590

188,083

-

Equity offering costs

(360)

(4)

Proceeds from option exercises

888

2,431

Net cash provided by financing activities

114,402

107,949

Net (decrease) increase in cash and cash equivalents

(5,966)

1,626

Cash and cash equivalents, beginning of year

56,962

59,930

Cash and cash equivalents, end of period

$

50,996

$

61,556

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

June 30,

December 31,

2012

2011

(In thousands, except unit information)

ASSETS

Current assets:

Cash and cash equivalents

$

50,996

$

56,962

Accounts receivable, net

95,105

119,193

Risk management assets

21,995

4,322

Prepayments and other current assets

2,381

5,114

Total current assets

170,477

185,591

Property, plant and equipment, net

1,238,893

1,103,699

Intangible assets, net

160,391

192,425

Investments in unconsolidated affiliates

453,380

544,687

Escrow cash

1,848

1,848

Risk management assets

10,445

6,452

Other assets, net

27,851

29,895

Total assets

$

2,063,285

$

2,064,597

LIABILITIES AND MEMBERS' CAPITAL

Current liabilities:

Accounts payable

$

120,632

$

155,921

Accrued capital expenditures

19,712

7,033

Accrued interest

10,951

8,686

Accrued tax liability

729

1,182

Risk management liabilities

1,833

3,565

Other current liabilities

15,953

15,007

Total current liabilities

169,810

191,394

Long term debt (includes $3,263 and $0 bond premium as of June 30, 2012

and December 31, 2011, respectively)

1,007,788

994,525

Deferred tax liability

2,385

2,199

Other noncurrent liabilities

5,105

4,581

Commitments and contingencies

Members' capital:

Series A convertible preferred units, no par value, 12,275,579 units and

11,684,074 units issued and outstanding as of June 30, 2012 and

December 31, 2011, respectively

285,168

285,168

Common units, no par value, 72,365,674 units and 66,341,458 units issued and

outstanding as of June 30, 2012 and December 31, 2011, respectively

1,353,504

1,164,853

Paid in capital

67,034

62,277

Accumulated deficit

(834,712)

(624,121)

Accumulated other comprehensive income (loss)

7,203

(16,279)

878,197

871,898

Total liabilities and members' capital

$

2,063,285

$

2,064,597

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED RESULTS OF OPERATIONS

Three Months Ended

June 30,

Six Months Ended

June 30,

2012

2011

2012

2011

($ In thousands)

Total segment gross margin(1)

$

72,850

$

65,296

$

137,678

$

125,642

Operations and maintenance expenses

18,287

15,763

36,929

30,862

Depreciation and amortization

19,062

17,363

38,150

34,232

Impairment

-

-

28,744

-

General and administrative expenses

10,298

11,901

25,242

24,499

Taxes other than income

2,110

1,397

3,476

2,527

Equity in (earnings) loss from unconsolidated affiliates(2)(3)

(12,437)

(1,306)

102,291

(3,008)

Operating income (loss)

35,530

20,178

(97,154)

36,530

Loss on refinancing of unsecured debt

-

(18,233)

-

(18,233)

Interest and other financing costs, net

(14,081)

(11,446)

(28,467)

(23,355)

Provision for income taxes

(331)

140

(932)

(771)

Net income (loss)

21,118

(9,361)

(126,553)

(5,829)

Preferred unit distributions

(8,915)

(8,076)

(17,613)

(15,956)

Net income (loss) to common units

$

12,203

$

(17,437)

$

(144,166)

$

(21,785)

Basic net income (loss) per common unit

$

0.17

$

(0.26)

$

(2.01)

$

(0.33)

Weighted average number of common units - basic

72,300

66,143

71,630

66,065

Diluted net income (loss) per common unit

$

0.14

$

(0.26)

$

(2.01)

$

(0.33)

Weighted average number of common units - diluted

85,176

66,143

71,630

66,065

Total segment gross margin:

Texas

$

49,101

$

46,134

$

94,442

$

91,145

Oklahoma

20,171

28,665

44,370

51,747

Rocky Mountains(4)

187

771

545

1,813

Segment gross margin

69,459

75,570

139,357

144,705

Corporate and other(5)

3,391

(10,274)

(1,679)

(19,063)

Total segment gross margin(1)

$

72,850

$

65,296

$

137,678

$

125,642

Segment gross margin per unit:

Texas:

Service throughput ($/MMBtu)

$

0.58

$

0.76

$

0.56

$

0.76

Oklahoma:

Service throughput ($/MMBtu)

$

0.68

$

1.11

$

0.76

$

1.03

Volumes:

Texas:(6)

Service throughput (MMBtu/d)(7)

924,465

665,040

934,257

660,741

Pipeline throughput (MMBtu/d)

566,388

444,186

565,949

422,429

Plant inlet volumes (MMBtu/d)

834,846

588,533

834,004

574,794

NGLs produced (Bbls/d)

50,146

26,913

42,745

25,080

Oklahoma:(8)

Service throughput (MMBtu/d)(7)

324,915

283,870

321,600

280,293

Plant inlet volumes (MMBtu/d)

158,106

157,424

157,579

156,856

NGLs produced (Bbls/d)

17,028

17,331

16,994

17,067

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED RESULTS OF OPERATIONS

Capital Expenditures:

Maintenance capital expenditures

$

3,798

$

5,555

$

6,241

$

7,601

Expansion capital expenditures

115,562

69,382

163,925

120,901

Total capital expenditures

$

119,360

$

74,937

$

170,166

$

128,502

Operations and maintenance expenses:

Texas

$

11,275

$

8,908

$

21,893

$

17,733

Oklahoma

6,962

6,794

14,943

13,013

Rocky Mountains

50

61

93

116

Total operations and maintenance expenses

$

18,287

$

15,763

$

36,929

$

30,862

(1)

Total segment gross margin is a non-GAAP financial measure. Please read "Unaudited Non-GAAP Financial Measures" for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.

(2)

During the three months ended March 31, 2012, Copano recorded a $120 million non-cash impairment charge relating to its investments in Bighorn and Fort Union.

(3)

The following table summarizes the results and volumes associated with our unconsolidated affiliates ($ in thousands):

Three Months Ended June 30,

2012

2011

Volume

Equity (Earnings)/Loss

Volume

Equity (Earnings)/Loss

Eagle Ford Gathering

$ (9,846)

$ 8

Pipeline throughput

(MMBtu/d)

252,912

—

NGLs produced(a)

(Bbls/d)

10,169

—

Liberty Pipeline Group

(Bbls/d)

22,379

139

—

1

Webb Duval(b)

(MMBtu/d)

63,199

(47)

48,045

(18)

Southern Dome

(13)

(669)

Plant inlet

(MMBtu/d)

7,352

11,730

NGLs produced

(Bbls/d)

249

432

Bighorn and Fort Union(c)

(MMBtu/d)

747,009

(2,574)

533,329

(615)

Six Months Ended June 30,

2012

2011

Volume

Equity (Earnings)/Loss

Volume

Equity (Earnings)/Loss

Eagle Ford Gathering

$ (11,908)

$ 38

Pipeline throughput

(MMBtu/d)

229,991

—

NGLs produced(a)

(Bbls/d)

10,040

—

Liberty Pipeline Group

(Bbls/d)

17,690

274

—

1

Webb Duval(b)

(MMBtu/d)

62,567

(190)

48,744

184

Southern Dome

(401)

(1,371)

Plant inlet

(MMBtu/d)

8,684

11,457

NGLs produced

(Bbls/d)

306

413

Bighorn and Fort Union(c)

(MMBtu/d)

767,188

114,711

557,059

(1,834)

____________________________________

(a) Net of NGLs produced at our Houston Central complex

(b) Net of intercompany volumes

(c) Changes in pipeline throughput at Fort Union did not have a material impact on gross margin because Fort Union received payments for additional volumes under long-term contractual commitments in each of the periods indicated

Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including plants owned by the Oklahoma segment and plants owned by third parties.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED NON-GAAP FINANCIAL MEASURES

Three Months Ended June 30,

Six Months Ended June 30,

2012

2011

2012

2011

Reconciliation of total segment gross margin to operating income (loss):

(In thousands)

Operating income (loss)

$

35,530

$

20,178

$

(97,154)

$

36,530

Add: Operations and maintenance expenses

18,287

15,763

36,929

30,862

Depreciation and amortization

19,062

17,363

38,150

34,232

Impairment

-

-

28,744

-

General and administrative expenses

10,298

11,901

25,242

24,499

Taxes other than income

2,110

1,397

3,476

2,527

Equity in (earnings) loss from unconsolidated affiliates

(12,437)

(1,306)

102,291

(3,008)

Total segment gross margin

$

72,850

$

65,296

$

137,678

$

125,642

Reconciliation of EBITDA, adjusted EBITDA and total distributable

cash flow to net income (loss):

Net income (loss)

$

21,118

$

(9,361)

$

(126,553)

$

(5,829)

Add: Depreciation and amortization

19,062

17,363

38,150

34,232

Interest and other financing costs

14,602

11,454

29,026

23,370

Provision for income taxes

331

(140)

932

771

EBITDA

55,113

19,316

(58,445)

52,544

Add: Amortization of commodity derivative options

5,039

7,357

10,078

14,627

Distributions from unconsolidated affiliates

12,185

7,099

22,514

13,572

Loss on refinancing of unsecured debt

-

18,233

-

18,233

Equity-based compensation

1,121

4,109

4,352

7,091

Equity in (earnings) loss from unconsolidated affiliates

(12,437)

(1,306)

102,291

(3,008)

Unrealized (gain) loss from commodity risk management activities

(4,980)

180

(4,401)

(363)

Impairment

-

-

28,744

-

Other non-cash operating items

2,252

(572)

3,485

(848)

Adjusted EBITDA

58,293

54,416

108,618

101,848

Less: Interest expense

(14,548)

(10,988)

(28,781)

(22,594)

Current income tax expense and other

(418)

(293)

(747)

(624)

Maintenance capital expenditures

(3,798)

(5,555)

(6,241)

(7,601)

Total distributable cash flow(1)

$

39,529

$

37,580

$

72,849

$

71,029

Actual quarterly distribution

$

42,336

$

38,687

Total distributable cash flow coverage

93

%

97

%

(1)

Prior to any retained cash reserves established by Copano's Board of Directors